All crude oil contains impurities which can contribute to corrosion, heat exchanger fouling, furnace coking, catalyst deactivation and product degradation in refining and other processes. These contaminants are broadly classified as bottom sediment, water, filterable solids, organometalics and salts. The amounts of these impurities vary depending upon the particular crude. Generally, crude oil salt content ranges between about 3 and 200 pounds per 1000 barrels.
Mineral salts present in crude oil include predominantly sodium chloride with lesser amounts of magnesium chloride, calcium chloride, calcium and magnesium carbonates, bicarbonates and sulfates. The mineral salts are a result of long contact of water and crude oil with salty substrates and soil.
If crude oil is not desalted, the inorganic salts can cause corrosion problems in metal refining equipment. Chlorine bearing acidic salts such as CaCl.sub.2 and MgCl.sub.2 tend to hydrolyze to form HCl during handling of crude oil containing inorganic salts. If left untreated HCl can be a major source of metal corrosion. Even if treated with neutralizing amines, the resulting salt deposits can be corrosive. Divalent and trivalent cations such as Fe.sup.+2, Fe.sup.+3 and Al.sup.+3, if not removed, remain in the refining residual and degrade the value of coke or carbon black made from the residual. Furthermore, solubilization or evaporation of water in heated crude can precipitate acidic, corrosive di- and trivalent chlorine salts which can foul heat exchangers, pipes and vessel surfaces.
Desalting processes remove primarily inorganic salts from the crude prior to refining. The desalting step is provided by adding and mixing with the crude a few volume percentages of fresh water to the crude oil.
In crude oil desalting, a water-in-oil emulsion is intentionally formed with the water admitted being on the order of about 2 to 12 volume percent based on the crude oil. Water is added to the crude oil and mixed intimately to transfer salts in the crude oil to the water phase. Separation of the phases occurs due to coalescence of the small water droplets into progressively larger droplets and eventual gravity separation of the oil and underlying water phase. A residue of the aqueous phase generally remains in the desalted crude; however, the salt content of the crude is reduced due to the desalting step.
Demulsification agents are added, usually upstream from the desalter to help in providing maximum mixing of the oil and water phases in the desalter. Known demulsifying agents include alkoxylated alkylphenolformaldehyde resins, a variety of polyesters, alkoxylated polyols, polyepoxides of these materials, cationic water soluble polymers, and many other commercially available compounds.
Desalters are also commonly provided with electrodes to impart an oscillating electric field in the desalter. This serves to polarize the dispersed water droplets. The so formed dipole droplets exert an attractive force between oppositely charged poles with the increased attractive force increasing the number of water droplet collisions. The water droplets elongate in the electrical field, thus creating more surface area that further enhances coalescence. Overall, the coalescence rate increases from 10 to 100 fold.
Upon separation of the phases from the water-in-oil emulsion, the crude is commonly drawn off the top of the desalter and sent to the fractionator tower in crude units or other refinery processes. The water phase containing water soluble inorganic salt compounds, water soluble organic contaminants, and water wet sediment is discharged as effluent.
Desalters are typically employed in tandem arrangement to improve salt removal efficacy. Commonly, in such designs, crude oil from the resolved emulsion in the upstream, first desalter is used as crude feed to the downstream second desalter. Fresh wash water is added to the crude stream fed to the second desalter, with water phase bottoms effluent from the second desalter being fed back as wash water to mix with the fresh crude fed to the first desalter.
Due to the advantage of heat in aiding separation, in a conventional system the crude oil fed to the first stage desalter is preheated prior to mixing with the effluent water from the second stage in feeding to the desalter unit. Thus, in a conventional two-stage desalter system both the first and second stage of the desalter train are operated at elevated temperatures.
Typically, desalters are operated at about 90.degree. to 150.degree. C. Heat lowers the viscosity of the oil thereby speeding the migration of the coalesced water droplets to the vessel interface as governed by Stokes law. It also increases the ability of oil to dissolve certain organic emulsion stabilizers such as surfactants that may have been added or are naturally occurring in the crude.
Desalter pressure is kept high enough to prevent crude oil or water vaporization. Desalter pressures at operating temperatures are generally about 20 psi to 100 psi above the crude oil or water vapor pressure, whichever is higher.
Emulsion breakers, also called the demulsifiers, are usually fed to the crude so as to modify the stabilizer film formed initially at the oil/water interface. Obverse emulsion breakers are relatively lipophilic surfactants, typically polymeric, that mitigate rigid interfacial barriers between water droplets allowing droplets of water in oil to coalesce more readily. Reverse emulsion breakers are relatively hydrophilic polymers, typically surface active, that mitigate the repulsive interfacial forces between oil droplets, allowing the droplets of oil in water to coagulate more readily. These demulsifiers reduce the residence time required for good separation of oil and water.
It is generally desirable to desalt crude oil shortly after production from a subterranean oil bearing formation in order to minimize the fouling and corrosion problems caused by inorganics during crude oil handling and refining. However, fresh water for desalting of crude oil is not always available or in sufficient supply at locations where crude oil is produced, such as in the Middle East, parts of North America and on off-shore oil production sites. Thus, a need exists for a method to desalt crude oil which does not require the use of fresh water. Additionally, water soluble organic compounds such as benzene, phenols and volatile organic compounds (VOC's) in aqueous effluent from desalting operations can be harmful to the environment and thus are under increasing government restriction.
In order to minimize effluent from desalting operations, recycling of effluent water is desirable if the corrosion reducing efficacy of the recycled water is retained. Recycling reduces the effluent volume and increases the salinity of the reused wash water, which decreases the partitioning of organics into the effluent brine relative to the crude oil. However, merely increasing the salinity of the effluent wash water also increases the carry over in the desalted crude of residual corrodent inorganic materials proportionally. Therefore, a need exists for a method of recycling desalter wash water which does not increase the residual corrodent material in washed crude oil.
Also, some heavy crudes have densities about the same as fresh water. Such heavy crudes are very difficult or impossible to desalt using fresh water due to insufficient force driving the stratification of the oil and water phases. A need therefore exists for a method of desalting heavy crudes employing an aqueous phase which is more dense than the heavy crude, yet is still effective for removing corrosive inorganic salts from the crude.
It is therefore an object of this invention to provide a method for removing corrodent inorganic material from crude oil which does not require the use of fresh water, and which thus avoids the problems inherent with the use of fresh water in crude oil desalting methods.